U.S. patent application number 12/370221 was filed with the patent office on 2009-08-20 for real time misalignment correction of inclination and azimuth measurements.
This patent application is currently assigned to Baker Hughes Incorporated. Invention is credited to Hanno Reckmann, Bernd Santelmann, Frank Schuberth.
Application Number | 20090205867 12/370221 |
Document ID | / |
Family ID | 40954070 |
Filed Date | 2009-08-20 |
United States Patent
Application |
20090205867 |
Kind Code |
A1 |
Reckmann; Hanno ; et
al. |
August 20, 2009 |
Real Time Misalignment Correction of Inclination and Azimuth
Measurements
Abstract
A method for determining wellbore trajectory includes
determining survey parameters in the wellbore; measuring force
parameter(s) in the wellbore; and correcting the survey parameters
using the measured force parameter(s). The downhole measured force
parameters may include forces associated with an operation of a
steering device such as an internal reaction force, and/or a
bending moment. In variants, the method may include measuring a
wellbore temperature; measuring a wellbore parameter in addition to
the temperature; and correcting a survey parameter using the
measured parameter and the measured temperature. These methods may
include correcting survey parameters using measured wellbore
diameters. Also, a processor in the wellbore may be programmed to
perform the correction while in the wellbore and/or control a
steering device using measurements provided by a sensor for
measuring internal reaction forces.
Inventors: |
Reckmann; Hanno; (Humble,
TX) ; Schuberth; Frank; (Hannover, DE) ;
Santelmann; Bernd; (Boehme, DE) |
Correspondence
Address: |
MADAN & SRIRAM, P.C.
2603 AUGUSTA DRIVE, SUITE 700
HOUSTON
TX
77057-5662
US
|
Assignee: |
Baker Hughes Incorporated
Houston
TX
|
Family ID: |
40954070 |
Appl. No.: |
12/370221 |
Filed: |
February 12, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61029161 |
Feb 15, 2008 |
|
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|
Current U.S.
Class: |
175/24 ; 175/45;
175/73 |
Current CPC
Class: |
E21B 7/062 20130101;
E21B 47/024 20130101 |
Class at
Publication: |
175/24 ; 175/45;
175/73 |
International
Class: |
E21B 47/022 20060101
E21B047/022; E21B 7/06 20060101 E21B007/06; E21B 7/08 20060101
E21B007/08; E21B 7/04 20060101 E21B007/04; E21B 47/024 20060101
E21B047/024; E21B 47/06 20060101 E21B047/06; E21B 47/08 20060101
E21B047/08 |
Claims
1. A method for determining a trajectory of a wellbore drilled in
an earthen formation, comprising: (a) determining at least one
survey parameter at a location in the wellbore; (b) measuring at
least one force parameter in the wellbore; and (c) correcting the
at least one survey parameter using the at least one measured force
parameter.
2. The method according to claim 1, wherein the downhole measured
force parameter is: (i) a force associated with an operation of a
steering device, and (ii) bending moment.
3. The method according to claim 1, further comprising measuring a
wellbore diameter and correcting the at least one survey parameter
using the measured wellbore diameter.
4. The method according to claim 1, wherein the at least one force
parameter is measured at substantially the same time the at least
one survey parameter is determined.
5. The method according to claim 1, further comprising conveying a
processor into the wellbore, wherein the correcting is performed by
the processor while in the wellbore.
6. The method according to claim 1, further comprising conveying a
drill string into the wellbore; and determining a bend attributable
to the measured at least one force parameter.
7. The method according to claim 1, further comprising conveying a
drill string into the wellbore; and steering the drill string using
the corrected at least one survey parameter.
8. The method according to claim 1, wherein the at least one survey
parameter includes azimuth and inclination.
9. The method according to claim 8, further comprising: determining
at least one survey parameter at a plurality of locations in the
wellbore; measuring at least one force parameter in the wellbore at
the plurality of locations; and correcting the at least one survey
parameter determined at each of the locations using the at least
one force parameter measured at each of the locations.
10. The method according to claim 1, wherein the downhole measured
parameter is a normal force associated with a wellbore engagement
device engaging a wellbore wall.
11. The method according to claim 1, further comprising estimating
at least one directional coordinate for a selected wellbore device
along the drill string using the corrected at least one survey
parameter.
12. The method according to claim 1, wherein the at least one
measured force parameter is an internal reaction force caused by
operation of a steering device.
13. A method for determining a trajectory of a wellbore drilled in
an earthen formation, comprising: (a) determining at least one
survey parameter at a location in the wellbore; (b) measuring a
temperature in the wellbore; (c) measuring at least one parameter
in the wellbore in addition to the temperature; and (d) correcting
the at least one survey parameter using the at least one measured
parameter and the measured temperature.
14. The method according to claim 13, wherein the at least one
parameter in the wellbore is one of: (i) a force associated with an
operation of a steering device, and (ii) bending moment.
15. The method according to claim 13, further comprising measuring
a wellbore diameter and correcting the at least one survey
parameter using the measured wellbore diameter.
16. The method according to claim 13, further comprising conveying
a processor into the wellbore, wherein the correcting is performed
by the processor while in the wellbore.
17. The method according to claim 13, further comprising conveying
a drill string into the wellbore; and steering the drill string
using the corrected at least one survey parameter.
18. The method according to claim 12, wherein the at least one
parameter is an internal reaction force caused by operation of a
steering device.
19. A computer-readable medium for use with an apparatus for
correcting survey data relating to a drilled wellbore, the
apparatus comprising: a drill string configured to be conveyed into
a wellbore in the earth formation; a steering device configured to
steer the drill string; a survey tool for measuring at least one
survey parameter, an a sensor for measuring at least one force
parameter; the medium comprising: instructions that enable at least
one processor to correct the measured at least one survey parameter
using the measured at least one force parameter.
20. The medium of claim 19 further comprising at least one of: (i)
a ROM, (ii) an EPROM, (iii) an EEPROM, (iv) a flash memory, and (v)
an optical disk.
21. An apparatus for steering a drill string, comprising: a
steering device having at least one pad configured to apply a force
to a wall of a wellbore; and a force measurement sensor configured
to measure a reaction force associated with the force applied by
the at least one pad.
22. A method for controlling a steering device for steering a drill
string, comprising: (a) operating the steering device to apply a
force to a wall of the wellbore; (b) measuring a reaction force
associated with the force applied by the steering device; and (c)
controlling the steering device in response to the measured
reaction force.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application takes priority from the U.S. Provisional
Application Ser. No. 61/029,161, filed on Feb. 15, 2008.
BACKGROUND OF THE DISCLOSURE
[0002] 1. Field of the Disclosure
[0003] This disclosure relates generally to oilfield downhole tools
and more particularly to methods and devices for enhanced
directional drilling of wellbores.
[0004] 2. Description of the Related Art
[0005] To obtain hydrocarbons such as oil and gas, boreholes or
wellbores are drilled by rotating a drill bit attached to the
bottom of a BHA (also referred to herein as a "Bottom Hole
Assembly" or ("BHA"). The BHA is attached to the bottom of a
tubing, which is usually either a jointed rigid pipe or a
relatively flexible spoolable tubing commonly referred to in the
art as "coiled tubing." The string comprising the tubing and the
BHA is usually referred to as the "drill string." When jointed pipe
is utilized as the tubing, the drill bit is rotated by rotating the
jointed pipe from the surface and/or by a mud motor contained in
the BHA. In the case of a coiled tubing, the drill bit is rotated
by the mud motor. During drilling, a drilling fluid (also referred
to as the "mud") is supplied under pressure into the tubing. The
drilling fluid passes through the BHA and then discharges at the
drill bit bottom. The drilling fluid provides lubrication to the
drill bit and carries to the surface rock pieces disintegrated by
the drill bit in drilling the wellbore. The mud motor is rotated by
the drilling fluid passing through the BHA. A drive shaft connected
to the motor and the drill bit rotates the drill bit.
[0006] In addition to vertically aligned wells, a substantial
proportion of the current drilling activity involves drilling of
deviated and horizontal wellbores to more fully exploit hydrocarbon
reservoirs. Irrespective of the well profile, however, it is
essential to place the well bore trajectory as precisely as
possible to optimally produce hydrocarbons. Conventionally, a
trajectory of a drilled wellbore is defined by measuring
inclination and azimuth at discrete survey stations while drilling.
From these angular measurements and together with the length of the
drill string, the trajectory can be reconstructed. Azimuth and
inclination may be measured by survey sensors positioned along the
drill string. The bending of the part of the string where the
sensors are placed may "sag" and cause the borehole centerline to
not necessarily point in the same direction as the centerline of
the MWD tool with the sensors.
[0007] The present disclosure addresses the need for systems and
devices that correct for errors caused by misalignment, sag or
bending in survey measurements.
SUMMARY OF THE DISCLOSURE
[0008] In aspects, the present disclosure provides systems and
methods for determining a trajectory of a wellbore drilled in an
earthen formation. The method may be used in connection with a
drill string having one or more sensors configured to measure
parameters relating to the downhole environment, the wellbore being
drilled, the drill string being used to drill the wellbore, and/or
forces that are applied to the drill string. In one embodiment, the
method includes determining one or more survey parameters at a
location in the wellbore using suitable survey instruments;
measuring one or more force parameters in the wellbore using one or
more sensors provided on the drill string; and correcting the
survey parameter using the measured force parameter. The downhole
measured force parameter may be a force associated with an
operation of a steering device, and/or a bending moment. The
downhole measured parameter may also be a normal force associated
with a wellbore engagement device such as a centralizer or
stabilizer that engages a wellbore wall. Moreover, the method may
include measuring a wellbore diameter and correcting the survey
parameter using the measured wellbore diameter. The method may be
utilized in real-time or near real-time. For instance, in certain
applications, the force parameter may be measured at approximately
the same time that the survey parameter is determined.
Additionally, the method may be performed in situ in the wellbore.
Thus, in certain embodiments, the method may include conveying into
the wellbore a processor that is programmed to perform the
correction while in the wellbore. Further, in certain applications,
the method may include estimating at least one directional
coordinate for a selected wellbore device along the drill string
using the corrected at least one survey parameter.
[0009] In one illustrative application, a drill string may be
conveyed into the wellbore and the method may be used to determine
a bend attributable to one or more force parameters measured in the
wellbore. In another illustrative application, the method may be
used to steer a drill string by using one or more survey parameters
that have been corrected. Illustrative survey parameters include
azimuth and inclination.
[0010] In aspects, the method may be used to provide continuous
corrected survey data during drilling. For example, the method may
include determining survey parameters at a plurality of locations
in the wellbore; measuring a force parameter in the wellbore at the
plurality of locations; and correcting the survey parameter
determined at each of the locations using the force parameter
measured at each of the locations.
[0011] In aspects, the present disclosure also provides a method
for determining a trajectory of a wellbore drilled in an earthen
formation that includes determining at least one survey parameter
at a location in the wellbore; measuring a temperature in the
wellbore; measuring at least one parameter in the wellbore in
addition to the temperature; and correcting the at least one survey
parameter using the at least one measured parameter and the
measured temperature.
[0012] In aspects, the present disclosure further provides a
computer-readable medium for use with an apparatus for correcting
survey data relating to a drilled wellbore. The apparatus may
include a drill string configured to be conveyed into a wellbore in
the earth formation, a steering device configured to steer the
drill string, a survey tool for measuring at least one survey
parameter, and a sensor for measuring at least one force parameter.
The medium may include instructions that enable at least one
processor to correct the measured at least one survey parameter
using the measured at least one force parameter. In arrangements,
the medium may also include (i) a ROM, (ii) an EPROM, (iii) an
EEPROM, (iv) a flash memory, and (v) an optical disk.
[0013] In still other aspects, the present disclosure provides an
apparatus for steering a drill string. The apparatus may include a
steering device having at least one pad configured to apply a force
to a wall of a wellbore and a force measurement sensor configured
to measure a reaction force associated with the force applied by
the at least one pad. An illustrative method for controlling a
steering device for steering a drill string may include operating
the steering device to apply a force to a wall of the wellbore;
measuring a reaction force associated with the force applied by the
steering device; and controlling the steering device in response to
the measured reaction force.
[0014] Illustrative examples of some features of the disclosure
thus have been summarized rather broadly in order that the detailed
description thereof that follows may be better understood, and in
order that the contributions to the art may be appreciated. There
are, of course, additional features of the disclosure that will be
described hereinafter and which will form the subject of the claims
appended hereto.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] For detailed understanding of the present disclosure,
references should be made to the following detailed description of
the preferred embodiment, taken in conjunction with the
accompanying drawings, in which like elements have been given like
numerals and wherein:
[0016] FIG. 1 illustrates a drilling system made in accordance with
one embodiment of the present disclosure;
[0017] FIG. 2 illustrates in schematic format a BHA having a
processor programmed to determine sag or bending correction in
accordance with one embodiment of the present disclosure;
[0018] FIG. 3 illustrates the effect of sag or bending on a
position of a survey tool;
[0019] FIG. 4 illustrates in functional format exemplary methods
for employing sag or bending correction using real time
measurements;
[0020] FIG. 5 schematically illustrates a steering device utilizing
a force measurement sensor in accordance with one embodiment of the
present disclosure; and
[0021] FIG. 6 sectionally illustrates the FIG. 5 embodiment and
associated forces.
DETAILED DESCRIPTION OF THE DISCLOSURE
[0022] The present disclosure relates to devices and methods for
obtaining accurate survey values for wellbore and for more accurate
directional drilling of wellbores. In part, such accuracy is
obtained by correcting survey measurements for physical distortion
in a drill string at which one or more directional survey
instruments are positioned. The present disclosure is susceptible
to embodiments of different forms. The drawings show and the
written specification describes specific embodiments of the present
disclosure with the understanding that the present disclosure is to
be considered an exemplification of the principles of the
disclosure, and is not intended to limit the disclosure to that
illustrated and described herein. Further, while embodiments may be
described as having one or more features or a combination of two or
more features, such a feature or a combination of features should
not be construed as essential unless expressly stated as
essential.
[0023] Referring now to FIG. 1, there is shown an embodiment of a
drilling system 10 utilizing a bottomhole assembly (BHA) 60
configured for directionally drilling wellbores. As will be
appreciated from the discussion below, the correction methodologies
and systems according to the present disclosure may provide greater
accuracy in placing a wellbore in the formation. In aspects, the
correction for misalignment, sagging or bending in a drill string
may be applied in real time to the directional survey taken in the
wellbore. Therefore, the steerable drilling assemblies may be
guided with better accuracy and may require fewer course
corrections. Additionally, the increased precision in the
directional surveys may enhance the quality of
directionally-sensitive MWD measurements made during drilling.
Additionally, the use of force measurement sensors as described
herein may enhance tool service life and efficiency by providing an
indication of "out of norm" or otherwise undesirable operating
conditions.
[0024] In one embodiment, the system 10 shown in FIG. 1 includes a
bottomhole assembly (BHA) 60 conveyed in a borehole 12 as part of a
drill string 22. The drill string 22 includes a tubular string 24,
which may be jointed drill pipe or coiled tubing, extending
downward into the borehole 12 from a rig 14. The drill bit 62,
attached to the drill string end, disintegrates the geological
formations when it is rotated to drill the borehole 12. The drill
string 22, which may be jointed tubulars or coiled tubing, may
include power and/or data conductors such as wires for providing
bi-directional communication and power transmission. The present
disclosure is not limited to any particular rig or drilling
assembly configuration. In some rig arrangements, the drill string
22 is coupled to a drawworks 26 via a kelly joint 28, swivel 30 and
line 32 through a pulley (not shown). More commonly, a rig may use
a rotary top drive system. Also the drilling system may be a simple
rotary system, or a rotary steerable system.
[0025] In arrangements, a surface controller 50 receives signals
from the downhole sensors and devices via a sensor 52 placed in the
fluid line 42 and signals from sensors S.sub.1, S.sub.2, S.sub.3,
hook load sensor S.sub.4 and any other sensors used in the system
and processes such signals according to programmed instructions
provided to the surface controller 50. The surface controller 50
displays desired drilling parameters and other information on a
display/monitor 54 and is utilized by an operator to control the
drilling operations. A communication system for transmitting
uplinks and downlinks may include a mud-driven power generation
units (mud pursers), or other suitable two-way communication
systems that use hard wires (e.g., electrical conductors, fiber
optics), acoustic signals, EM or RF.
[0026] The BHA 60 may include a formation evaluation sub 61 that
may includes sensors for determining parameters of interest
relating to the formation, borehole, geophysical characteristics,
borehole fluids and boundary conditions. These sensor include
formation evaluation sensors (e.g., resistivity, dielectric
constant, water saturation, porosity, density and permeability),
sensors for measuring borehole parameters (e.g., borehole size, and
borehole roughness), sensors for measuring geophysical parameters
(e.g., acoustic velocity and acoustic travel time), sensors for
measuring borehole fluid parameters (e.g., viscosity, density,
clarity, rheology, pH level, and gas, oil and water contents), and
boundary condition sensors, sensors for measuring physical and
chemical properties of the borehole fluid. The BHA 60 may also
include a processor 100, sensors 56 configured to measure various
parameters of interest, and one or more survey instruments 58, all
of which are described in greater detail below.
[0027] Referring now to FIG. 2, there is shown in greater detail
certain elements of the BHA 60. The BHA 60 carries the drill bit 62
at its bottom or the downhole end for drilling the wellbore and is
attached to a drill pipe 64 at its uphole or top end. A mud motor
or drilling motor 66 above or uphole of the drill bit 62 may be a
positive displacement motor, which is well known in the art. A
turbine may also be used. Fluid supplied under pressure via the
drill pipe 64 energizes the motor 66, which rotates the drill bit
62.
[0028] The BHA 60 also includes a first steering device 70 that
contains one or more expandable ribs 72 that are independently
controlled to exert a desired force on the wellbore wall to steer
the drill bit 62 during drilling of the borehole. Each rib 72 can
be adjusted to any position between a collapsed position and a
fully extended position to apply the desired force vector to the
wellbore wall. A second steering device 74 may disposed a suitable
distance uphole of the first steering device 70. The steering
device 74 also includes a plurality of independently controlled
ribs 76. The force applied by the ribs 76 may be different from
that applied by the ribs 72. One or more fixed stabilizers 78 may
be disposed uphole of the second steering device 74. In the BHA
configuration 60, the drill bit 62 may be rotated by the drilling
motor 66 and/or by rotating the drill pipe 64. Thus, the drill pipe
rotation may be superimposed on the drilling motor rotation for
rotating the drill bit 62. The steering devices 70 and 74 may each
have three ribs 72, 76 or pads for adequate control of the steering
direction at each such device location. Fewer or greater number of
ribs may be utilized in certain configurations. The ribs may be
extended by any suitable method, such as a hydraulic system driven
by the drilling motor that utilizes the drilling fluid or by a
hydraulic system that utilizes sealed fluid in the BHA or by an
electro-hydraulic system wherein a motor drives the hydraulic
system or an electromechanical system wherein a motor drives the
ribs. Any suitable mechanism for operating the ribs may be utilized
for the purpose of this invention. One or more sensors 80 may be
provided to measure the displacement of and/or the force applied by
each rib 72, 76.
[0029] In embodiments, sensors may also be utilized to determine
forces associated with fixed blade devices that are configured to
engage a wellbore wall. Exemplary devices include centralizers or
stabilizers that have one or more fixed ribs or blades mounted on
the drill string or a non-rotating sleeve associated with the drill
string. These types of devices may apply a normal force that may
bend or deflect the drill string.
[0030] Referring now to FIG. 3, there is shown in simplified form a
portion of a borehole 90 having a borehole centerline 92, a curve
indicating a tool centerline 94 for a sagging section of a BHA 60
(FIG. 2) and a directional sensor 96. As can be seen, the sag
causes a misalignment between the tool centerline 94 on which the
directional sensor 96 is positioned and the centerline 92 of the
borehole. This misalignment translates into errors in the azimuth
measurements and inclination measurements taken by the directional
sensor 96. That is, a directional sensor 96 positioned at the
borehole centerline 92 may measure a different azimuth or
inclination than a directional sensor 96 positioned at the same
axial location and along the tool centerline 94. One factor that
causes the sag or bend in the BHA 60 may be gravity, which may be
significant because the BHA 60 may be tens of meters in length.
Moreover, other factors such as the forces exerted on the BHA 60
may also cause sag or bending the drill string 22. For this
discussion, it should be understood that the BHA 60 is a part of
the drill string 22. Thus, a reference to a bend in the drill
string 22 may encompass a bend in the BHA 60.
[0031] Referring now to FIGS. 2 and 3, in particular, the steering
devices 70, 74 may also impose forces on the BHA 60 that may
contribute to sag or other misalignment between the borehole
centerline 92 and the tool centerline 94. As discussed previously,
the ribs 72, 76 apply force to the borehole wall to steer the drill
bit 62 in a selected direction. These forces may also cause bending
along the BHA 60. Still other factors may include drilling dynamics
(e.g. weight on bit (WOB)) and environmental factors such as
temperature and pressure.
[0032] Referring now to FIGS. 2 and 4, in aspects of the present
disclosure, the BHA 60 may include a processor 100 programmed to
correct directional survey measurements for sag causes by any of
these or other factors. The processor 100 may be configured to
decimate data, digitize data, and include suitable PLC's. For
example, the processor may include one or more microprocessors that
uses a computer program implemented on a suitable machine-readable
medium that enables the processor to perform the control and
processing. The machine-readable medium may include ROMs, EPROMs,
EAROMs, Flash Memories and Optical disks.
[0033] In one arrangement, the processor 100 computes a sag or
bending correction using a pre-programmed mathematical model of the
BHA 60 and one or more real time or near-real time sensor
measurements. The model may predict the response of the BHA 60 to
one or more applied forces. These forces may be machine-induced
forces and/or natural forces. The response may be characterized as
a deflection, bending, twisting or other physical change to the
shape or orientation of the BHA 60. Based on the pre-programmed
model and the sensor measurements, the processor 100 calculates a
correction that may be applied to the azimuth and inclination
measurements provided by the directional survey tools. The
correction in one sense converts the measured directional survey
values to the directional values that would have been obtained if
the directional survey instruments 58 had been aligned with the
borehole centerline 92 (FIG. 3). The sensors and devices that may
provide data to the processor 100 for sag or bending correction
calculations are discussed below.
[0034] In embodiments, the processor 100 receives data from a
sensor sub 56 that may include sensors, circuitry and processing
software and algorithms for providing information that may cause
deflection or misalignment in the BHA 60. Such information may
include measurement of drilling parameters relating to the BHA,
drill string, the drill bit and downhole equipment such as a
drilling motor, steering unit, thrusters, etc. While the type and
number of sensors may depend upon the specific drilling
requirements, exemplary sensors may include drill bit sensors, an
RPM sensor, a weight on bit sensor, sensors for measuring BHA
operating parameters (e.g., mud motor stator temperature,
differential pressure across a mud motor, and fluid flow rate
through a mud motor), and sensors for measuring BHA or drill string
dynamics parameters such as acceleration, vibration, whirl, radial
displacement, stick-slip, torque, shock, vibration, strain, stress,
bending moment, bit bounce, axial thrust, friction, backward
rotation, BHA buckling and radial thrust. Other exemplary sensors
include, but are not limited to, sensors distributed along the
drill string that can measure drill string parameters or physical
quantities such as drill string acceleration and strain, internal
pressures in the drill string bore, vibration, electrical and
magnetic field intensities inside the drill string, bore of the
drill string, etc. Sensors for measuring internal reaction forces
caused by the operation of the steering device 70 is described in
greater detail later with reference to FIGS. 5-6. Still other
devices such as calipers may be used to determine borehole
parameters such as wellbore diameter. Suitable systems for making
dynamic downhole measurements include COPILOT, a downhole
measurement system, manufactured by BAKER HUGHES INCORPORATED. For
simplicity, these sensors, tools, and instruments have been
collectively referred to with numeral 56. Wellbore environmental
parameters such as external pressure in the annulus and temperature
may also be measured with suitable sensors.
[0035] The processor 100 may receive directional survey
measurements from survey instruments such as three (3) axis
accelerometers, magnetometers, gyroscopic devices and signal
processing circuitry as generally known in the art. For simplicity,
these sensors and instruments have been collectively referred to
with numeral 58.
[0036] In FIG. 4, there is shown the overall functional
relationship of the various aspects of the drilling system 60
described above. To effect drilling of a borehole, the BHA 60 is
conveyed into borehole. The processor 100 has been programmed with
one or more models 114 that predict the response of the BHA 60 to
one or more forces that may be encountered while drilling the
wellbore 12 and that may cause sag or other form of deflection of
the tool line 94 (FIG. 3) associated with the BHA 60. The operator
may set the initial drilling parameters to start the drilling along
a pre-planned trajectory. Either continuously or at periodic
intervals while downhole, the system 60 takes directional surveys
that may include azimuth and inclination 102, which may be
transmitted to the processor 100. Using the sensors previously
described, the processor 100 may receive measurements relating to
BHA operating parameters 104, borehole parameters 106 (e.g.,
measured wellbore diameter), force parameters relating to the drill
string 108 (e.g., bending moments in the BHA 60), force parameters
associated with the steering device 110 (e.g., from sensors 80 of
FIG. 2) and any other parameters 112 that may cause misalignment,
sag, bending or deflection in a section of the BHA 60 that includes
the directional survey instruments. These other parameters 112 may
include environmental parameters such as external pressure or
temperature. Some or all of these measurements may be taken in
real-time while downhole. Thus, for instance, for each survey
station along a drilled wellbore, the processor 100 may (i) obtain
one or more directional survey measurements, (ii) and values for
one or more parameters that could create errors in those
directional survey measurements. In a sense, therefore, the
correction to the survey measurements may be considered in
real-time because such activities are occurring while drilling is
on-going.
[0037] In one illustrative method, the processor 100 utilizes the
measured parameters and processes such values using the models 114
to determine a correction 116 for the measured azimuth and
inclination. The determined correction 116 may be utilized to
correct azimuth and inclination downhole 120 and to determine other
survey-related information such as vertical depth or true vertical
depth. The sag corrected survey measurements may then be utilized
for purposes such as steering 122 the BHA 60, the correlation of
MWD measurements 124, and/or stored for later use 126. The
processor 100 may also be programmed to dynamically adjust any
model or database as a function of the drilling operations. It
should be appreciated that with this method, the correction to
survey measurements is performed while drilling. It should also be
appreciated that, in embodiments, the corrected survey measurements
may be utilized to estimate a position of a selected location
either uphole or downhole of the survey instrument. For instance,
directional coordinates (azimuth, inclination, TVD) may be
estimated for a BHA tool such as a stabilizer or centralizer
positioned downhole of the survey instrument.
[0038] In another illustrative method, the processor 100 may
transmit data to the surface 130 for surface correction of
directional survey measurements for sag or bending. The processor
100 may transmit "raw" or partially processed data to the surface.
A surface processor may thereafter be used to correct the survey
measurements. In another arrangement, the processor 100 may
transmit uncorrected survey measurements and a calculated sag
correction. In this arrangement, the processing activity is shared
between the surface and the downhole processor. Thus, in
embodiments, the processing of data to determine corrected survey
measurements using real time data may be performed entirely
downhole, entirely at the surface, or using a combination of
downhole and surface computations.
[0039] Referring now to FIG. 5, there is shown one embodiment of a
sensor 200 that may be utilized to estimate a magnitude and/or
direction of a force associated with the steering devices 70, 74 or
other device that applies a force to the drill string 22. For ease
of discussion, reference is made to only the steering device 70. In
one arrangement, the sensor 200 may be utilized to estimate an
internal reaction force 210 associated with the steering device 70.
Referring now to FIG. 6, the ribs 72 of the steering device 70 are
shown applying steering forces 202, 204, 206 on a wellbore wall
208. Opposing the steering forces 202, 204, 206, is the reaction
force 210 that is applied via the steering device 70 to the drill
string. The reaction force 210 may be characterized as having a
magnitude and an azimuthal direction. The steering vector reaction
force is transmitted from the steering device 70 to the drill bit
62 (FIG. 2) via the structural components of the drill string 22
generally shown in FIG. 2. An illustrative reaction force 210
corresponding to the steering forces 202, 204, 206 may be
characterized as having a direction relative to a reference frame.
In one convention, the angular position of a device relative to a
reference frame, such as borehole highside, is defined as a "tool
face" of the device. Thus, the circumferential position at which
the reaction force 210 is applied to the steering device 70 may be
correlated with a selected formation reference point such as
borehole "highside," e.g., an internal reaction force may be
reported as an angle 214 (e.g., 90 degrees) from wellbore highside.
Embodiments of the present disclosure may utilize a force
measurement sensor at any suitable location along the structural
connection between the pads 72 of the steering device 70 and the
drill bit 62.
[0040] Referring now to FIG. 5, in one embodiment, a sensor 200 may
be positioned at or near an interface between a rotating member and
non-rotating section of the steering device 70. In one arrangement,
the sensor may be integrated into a bearing 205 between a rotating
drive shaft 216 and a non-rotating sleeve 218. The sensor 200 may
be fixed to and have a pre-determined or fixed angular orientation
relative to the non-rotating sleeve 218. Thus, when the directional
sensors determine a tool face of the non-rotating sleeve 218 or the
tool face of one or more of the pads 72, 74, 76 of the steering
device 70, the tool face angle of the sensor may also be determined
or estimated due to the fixed angular relationship between the
non-rotating sleeve 218 and the sensor 200. Exemplary sensors 200
for measuring force include strain gages, thin "sim" metal strain
gages, fiber optical gages, load cells, etc.
[0041] As shown in FIG. 5, the non-rotating sleeve 218 does not
rotate relative to the wellbore wall. While some slight rotation
may occur, the non-rotating sleeve 218 may be considered
rotationally stationary relative to the formation. In other
applications, the sensor may be positioned at an interface between
two members that each rotate relative to the formation and rotate
relative to one another (e.g., in top drive rotary steerable
systems, the drilling motor and its internal components such as
bearings may rotate with the drill string). Generally speaking,
therefore, the sensor may be positioned at any location, system or
component in the drill string wherein the reaction force is
measurable.
[0042] In other embodiments, the force measurement sensor 200 may
be separate from the bearing 205. For example, the sensor 200 may
be formed as a tubular member or sleeve that may be interposed
between the bearing 205 and the non-rotating section of the
steering device 70.
[0043] Referring now to FIGS. 5-6, in one illustrative method, the
steering device 70 via the ribs 72 apply a predetermined steering
force to the wellbore wall 208 to steer the bottomhole assembly 60
in a desired direction. During this steering, a processor utilizes
the measurements provided by the sensor 200 to estimate one or more
characteristics of the reaction force 210 being applied to the
steering device 70. One characteristic may be the magnitude of the
reaction force 210. Another characteristic may be the azimuthal
direction. In estimating the azimuthal direction, the processor may
first determine a circumferential position of the reaction force
210 on the sensor 200 and then estimate the angular offset of that
determined circumferential position relative to the tool face;
i.e., the processor may estimate the tool face angle 214 of the
reaction force 210.
[0044] In one arrangement, the processor may be a surface processor
50 (FIG. 1) that receives data from the sensor 200 in the wellbore.
The data may be raw data. Also, the data may be partially processed
or fully processed in order to reduce bandwidth requirements.
Personnel at the surface may utilize the sensor 200 data to
evaluate the operating conditions for the steering device 70. For
example, personnel may adjust the operation of the steering device
70 to maintain the reaction force 210 within a prescribed range or
norm.
[0045] Referring now to FIGS. 2, 4-6, in another arrangement, the
processor may be a downhole processor 100 that may be programmed
with models and algorithms 114 for operating the steering device 70
to maintain the reaction force 210 with a prescribed range or norm.
The prescribed range or norm may be based on considerations such as
accuracy of directional drilling or enhancing tool service life or
efficiency. In embodiments, the downhole processor 100 may control
the steering device 70 using, in part, the data provided by the
sensor 200.
[0046] Referring in particular to FIG. 4, to enhance steering
accuracy, the processor 100 may include a predictive model 114 that
estimates the magnitude and/or azimuthal direction of a reaction
force generated by the side forces applied by the steering device
70. Alternatively or additionally, the expected vector of the
reaction force may be preprogrammed. During drilling, the actual
magnitude and/or direction of the reaction force may be estimated,
shown by box 220, and compared with the expected or desired
reaction force. If the direction and/or magnitude varies more than
a predetermined amount, then the processor 100 may adjust the force
applied by the ribs 72 in a manner that substantially aligns the
measured reaction force with the desired reaction force, such
steering action shown by box 227. It will be appreciated that this
form of feed-back control allows the steering force applied by the
steering device 70 to be adjusted to account for the lithological
characteristics (e.g., hard formations) of the surrounding
formation.
[0047] To enhance tool life and/or efficiency, the processor 100
may receive force data, box 220, from the force measurement sensor
200 and/or inclination data, box 222, from an inclination sensor
226 (FIG. 5). Illustrative inclination sensors include single axis
and multi-axis accelerometers. The processor 100 may utilize the
inclination data 222 to estimate the stresses imposed on the
steering device 70 as well as other components of the BHA 60 that
are along the axis extending between the wellbore highside and low
side, or vertical axis. That is, if the measured inclination
exceeds an expected or desired inclination, it may be considered an
indication that the stresses imposed on the steering device 70 or
other component of the BHA 60 has exceeded a preset threshold.
Therefore, the processor 100 may adjust the steering device 70 to
reduce the steering force applied by the steering device 70. Also,
the processor 100 may utilize the force data 222 from the sensor
200 (FIG. 5) to estimate the internal forces applied to the
steering device 70 as well as other components of the BHA 60. In
particular, the force data 222 may provide an indication of the
internal forces along a horizontal axis orthogonal to the vertical
axis, this orthogonal axis being labeled with numeral 201 in FIG.
6. If the measured reaction force exceeds an expected or desired
reaction force, the processor 100 may adjust the steering device 70
to reduce the steering force applied by the steering device 70.
These steering adjustments and controls are shown by box 227. It
should be understood these particular applications of the use of
the force data 220 are merely illustrative and numerous other uses
may be available for the data furnished by the sensor 200. For
example, the measurements of internal reaction force may be
utilized in connection with the sag correction devices and
methodologies discussed earlier. While box 227 is shown as
utilizing data, such as directional data directly, in embodiments,
such data may be corrected for sag via the steps 130 and/or 116 of
FIG. 4 prior to adjusting the operation of the steering device
70.
[0048] From the above, it should be appreciated that what has been
described includes, in part, systems and methods for determining a
trajectory of a wellbore drilled in an earthen formation. The
method may be used in connection with a drill string having one or
more sensors configured to measure parameters relating to the
downhole environment, the wellbore being drilled, the drill string
being used to drill the wellbore, and/or forces that are applied to
the drill string. In one embodiment, the method may include
determining one or more survey parameters at a location in the
wellbore using suitable survey instruments; measuring one or more
force parameters in the wellbore using one or more sensors provided
on the drill string; and correcting the survey parameter using the
measured force parameter. The downhole measured force parameter may
be a force associated with an operation of a steering device,
and/or a bending moment. The downhole measured parameter may also
be a normal force associated with a wellbore engagement device such
as a centralizer or stabilizer that engages a wellbore wall.
Moreover, the method may include measuring a wellbore diameter and
correcting the survey parameter using the measured wellbore
diameter. The method may be utilized in real-time or near
real-time. For instance, in certain applications, the force
parameter may be measured at approximately the same time that the
survey parameter is determined. Additionally, the method may be
performed in situ in the wellbore. Thus, in certain embodiments,
the method may include conveying into the wellbore a processor that
is programmed to perform the correction while in the wellbore.
Further, in certain applications, the method may include estimating
at least one directional coordinate for a selected wellbore device
along the drill string using the corrected at least one survey
parameter.
[0049] What has been described further includes, in part, an
illustrative application wherein a drill string may be conveyed
into the wellbore and the method may be used to determine a bend
attributable to force parameters measured in the wellbore. In
another illustrative application, the method may be used to steer a
drill string by using survey parameters that have been
corrected.
[0050] What has been described also includes, in part, a method for
providing continuous corrected survey data during drilling. The
method may include determining survey parameters at several
locations in the wellbore; measuring a force parameter in the
wellbore at these locations; and correcting the survey parameter
determined at each of the locations using the force parameter
measured at each of the locations.
[0051] What has been described also includes, in part, a method for
determining a trajectory of a wellbore drilled in an earthen
formation that includes determining a survey parameter at a
location in the wellbore; measuring a temperature in the wellbore;
measuring a parameter in the wellbore in addition to the
temperature; and correcting the survey parameter using the measured
parameter and the measured temperature.
[0052] Still further, what has been described also includes, in
part, a computer-readable medium for use with an apparatus for
correcting survey data relating to a drilled wellbore. The
apparatus may include a drill string conveyed into a wellbore in
the earth formation, a steering device that steers the drill
string, a survey tool for measuring a survey parameter, and a
sensor for measuring a force parameter. The medium may include
instructions that enable the processor to correct the measured
survey parameter using the measured force parameter. In
arrangements, the medium may also include (i) a ROM, (ii) an EPROM,
(iii) an EEPROM, (iv) a flash memory, and (v) an optical disk. What
has been described also includes, in part, an apparatus for
steering a drill string. The apparatus may include a steering
device having pads that apply a force to a wall of a wellbore and a
force measurement sensor configured to measure a reaction
[0053] The foregoing description is directed to particular
embodiments of the present disclosure for the purpose of
illustration and explanation. It will be apparent, however, to one
skilled in the art that many modifications and changes to the
embodiment set forth above are possible without departing from the
scope of the disclosure. It is intended that the following claims
be interpreted to embrace all such modifications and changes.
* * * * *